Recent advancements in hydrocarbon recovery techniques have enabled the production of hydrocarbons from reservoirs that could not be produced economically without the use of such techniques. In particular, hydraulic fracturing (or “fracking”) involves the injection of a high pressure fluid (primarily water, proppants, and other job-specific compounds) to fracture a portion of a hydrocarbon-containing formation such that the desired hydrocarbons may be more easily recovered. Typically, multiple zones of a formation are independently isolated and fractured.
One common technique for isolating and fracturing different zones in a formation involves a process known as “plug-and-perf,” which process is illustrated in FIG. 1. This process may be utilized with various different arrangements of hydrocarbon production conduits. For example, conduit 106 may be production casing that is cemented into wellbore 104, a liner that is cemented in wellbore 104, or a liner that is situated within an open wellbore 104 (perhaps with swell packers isolating the annuli between the various zones). The plug-and-perf process can also be utilized with other production conduit arrangements, as is known by those of ordinary skill in the art.
The plug-and-perf process begins by isolating the zone for which hydraulic fracturing is to be performed from lower zones in the wellbore 104. This is accomplished by lowering a plug 100 into the well. In the example illustrated in FIG. 1, plug 100A is lowered to a desired location within the production conduit 106 from the surface of the well via a conveying apparatus 102 such as wireline, slickline, or coiled tubing (step 150A). It should be noted that the example illustrated in FIG. 1 assumes that a zone downhole (as used herein the terms “downhole” and “uphole” refer to locations that are further from and closer to the surface of a well, respectively) from ZONE 1 is to be isolated from the hydraulic fracturing operation performed in ZONE 1.
The plug 100A is then mechanically actuated (e.g., using a setting tool) to cause the plug to engage the production conduit 106 and isolate the portion of the production conduit 106 below the plug 100A from the portion of the production conduit 106 above the plug 100A (step 150B). In the illustrated example, the plug 100A is set by driving the shoulder 112A, which is disposed circumferentially about a mandrel 110A, toward a lower end of the plug 100A. As the shoulder 112A is forced downward, the cone 120A is driven behind the slips 122A causing the slips 122A to move radially outward from the plug 100A. The slips 122A include teeth that engage the interior wall of the production conduit 106 to prevent downward movement of the plug 100A. In addition, the sealing element 118A, which is constructed from an elastomeric material such as nitrile rubber, becomes deformed and contacts the interior wall of the production conduit 106 to form a fluid tight seal between the outer surface of the mandrel 110A and the interior wall of the production conduit 106. As the shoulder 112A continues to be forced downward, the cone 116A is driven under the slips 114A causing the slips 114A to move radially outward from the plug 100A. The slips 114A include teeth that engage the interior wall of the production conduit 106 to prevent upward movement of the plug 100A. Many plugs include mechanical devices (e.g., shear pins, etc.) that ensure that actuation of the various components of the plug occurs in a desired order (e.g., actuation of bottom slips 122A followed by deformation of sealing element 118A followed by actuation of top slips 114A, etc.). When the plug 100A has been fully actuated, its position is maintained within the production conduit 106 by the friction force between the slips 114A, 122A and the production conduit 106 and the fluid pathway outside of the plug 100A is sealed by the sealing element 118A. Thus, the only fluid path from above the plug 100A to below the plug 100A is through the plug bore 128A. While a general plug design has been shown for purposes of illustration, it will be understood that numerous other plug designs are employed to accomplish the same task.
After the plug 100A has been set, the production conduit 106 is perforated to create a fluid pathway between the hydrocarbon-containing formation and the interior of the production conduit 106 (step 150C). The perforations 132 penetrate through the production conduit 106 and typically extend at least some distance into the formation. Typically, perforations 132 are formed using a perforation gun 126A (shown only symbolically in the example of FIG. 1). A perforation gun 126A includes shape charges that, upon ignition (e.g., from the surface via a wireline), produce a jet of high pressure, high velocity gas that penetrates into the formation. In plug-and-perf operations, it is common for the perforation gun 126A to be conveyed into the production conduit 106 on the same conveying apparatus 102 that is used to convey the plug 100A, although this is not strictly necessary.
After the production conduit has been perforated above the plug 100A, the conveying apparatus 102 and the perforating gun 126A are removed from the well. To isolate the portion of the production conduit 106 above the plug 100A from the portion below, a frac ball 134 is conveyed down the production conduit 106 in a fracture fluid (the frac ball having a slightly greater density than the fracture fluid) until it comes to rest on the ball seat 130 of the plug 100A (step 150D). The ball seat 130A is complementary to the ball 134A, which allows the ball 134A to form a seal that prevents fluid from flowing downward through the bore 128A. The fracture fluid flows into the formation through the perforations 132, and, as the pressure of the fracture fluid is increased (often to pressures of 10,000 psi or greater), fractures 136A are formed in the formation in ZONE 1. Proppants in the fracture fluid hold the fractures 136A open even after the fracture fluid is removed from the well, which enables hydrocarbons in the formation to be extracted more efficiently. It should be noted that the plug 100A is exposed to the extreme pressures required to generate the fractures 136A and therefore its components (including the ball 134A) must maintain their mechanical integrity when exposed to such pressures to maintain the isolation of the production conduit 106 to ensure that the fracturing operation is focused on the intended zone.
After ZONE 1 has been fractured (i.e., fractures 136A have been formed), plug 100B is conveyed into the production conduit 106 on the conveying apparatus 102 to a desired location between the surface and the fractures 136A (step 150E). The process of plugging, perforating, and fracturing is then repeated to isolate and fracture each zone, moving in an uphole direction. When all of the zones have been fractured, the plugs must be milled or drilled out to enable hydrocarbons to flow to the surface of the well through the production conduit. While FIG. 1 illustrates a vertical portion of a well, hydraulic fracturing is often employed in horizontal portions of a well. It is not uncommon for a particular well, especially a horizontal well, to have 30-40 zones in which hydraulic fracturing is performed. Therefore, milling or drilling the numerous plugs can be a time-consuming and expensive operation. As such, there have been efforts to develop hydraulic fracturing techniques that avoid this requirement.
The first such technique employs sliding sleeve devices 200 as illustrated in FIG. 2. The sliding sleeve technique differs from the plug and perf technique in that the sliding sleeve devices 200 are integrated with the production conduit 106. For example, each sliding sleeve device 200 may be threaded to a string of the production conduit 106 (e.g., a liner) at its top and bottom ends. In the illustrated example, the sliding sleeve devices 200 are installed as part of the production conduit 106 in an open (i.e., uncemented and uncased) wellbore 104. In this type of application, the annulus between the production conduit 106 and the wellbore 104 may be sealed by packers 202 that separate the zones. Because the sliding sleeve devices 200 are integrated with the production conduit 106, additional planning and labor (as compared to the plug and perf technique) are required during the completion process to ensure that the sliding sleeve devices 200 are adjacent to zones to be stimulated and the packers 202 separate the various zones.
Although the sliding sleeve technique requires additional planning and labor during the completion process, it also simplifies the hydraulic fracturing process. In its initial state, a sliding sleeve 212A that is disposed within the body 214A of the sliding sleeve device 200A blocks radial ports 216A that extend through the body 214A, thus preventing fluid communication from the interior of the production conduit 106 to the wellbore 104 (step 250A).
The hydraulic fracturing process is initiated by conveying a frac ball 234A into the production conduit 106 with fracture fluid. This process is similar to the conveyance of the frac ball 134A into the production conduit 106 in the plug and perf process described with respect to FIG. 1. However, in the sliding sleeve technique, each frac ball 234 must pass through each of the sliding sleeve devices 200 located uphole from the sliding sleeve device 200 with which the ball is designed to mate (i.e., the ball's corresponding sliding sleeve device). Therefore, a frac ball 234 must have a diameter D234 that is smaller than the diameter D230 of each uphole ball seat 230 but greater than the diameter D230 of the ball seat 230 of its corresponding sliding sleeve device 200 (i.e., D230D, D230C, and D230B>D234A>D230A). For this to be accomplished at each zone, the diameters D230 of the ball seats 230 must be progressively smaller at increasing distances from the surface of the well (i.e., D230D>D230C>D230B>D230A, etc.).
After the ball 234A passes through the uphole sliding sleeve devices 200, it comes to rest on the ball seat 230A of the sliding sleeve device 200A (step 250B). Because the ball 234A cannot pass through the seat 230A, it forms a seal that prevents fluid from flowing downward through the sliding sleeve device 200A. As the pressure of the fracture fluid is increased, it is exerted in a downward direction on the ball 234A, which causes the sliding sleeve 212A to shift downward until the shoulder 236A of the sliding sleeve 212A contacts the shoulder 238A of the body of the sliding sleeve device 200A (step 250C). In the shifted position, the radial ports 216A are open to the interior of the sliding sleeve device 200A, thus enabling fluid communication from the interior of the production conduit 106 to the wellbore 104. The fracture fluid flows into the formation through the radial ports 216A, but the ball 230A continues to prevent fluid flow through the sliding sleeve device 200A and the packers 202A (not shown) and 202B prevent fluid flow in the annulus between the production conduit 106 and the wellbore 104. Consequently, the pressure of the fracture fluid acts only on the formation within ZONE 1, and, as the pressure is increased (often to pressures of 10,000 psi or greater), fractures 136A are formed in the formation. Just as with the plug and perf technique described above, proppants in the fracture fluid hold the fractures 136A open even after the fracture fluid is removed from the well, which enables hydrocarbons in the formation to be extracted more efficiently. Here again, it should be noted that the sliding sleeve device 200A is exposed to the extreme pressures required to generate the fractures 136A and therefore its components (including the ball 234A) must maintain their mechanical integrity when exposed to such pressures to maintain the isolation of the production conduit 106 to ensure that the fracturing operation is focused on the intended zone.
After ZONE 1 has been fractured (i.e., fractures 136A have been formed), the sliding sleeve process is repeated for the immediate uphole sliding sleeve device 200B (steps 250D through 250F) to isolate and fracture each zone, moving in the uphole direction. After all of the zones have been fractured, fluid is circulated in the reverse direction (i.e., the uphole direction) to remove the balls 234 from the production conduit. While the sliding sleeve technique is designed to eliminate the need for milling or drilling components after hydraulic fracturing is complete, it is not uncommon for a ball 234 to become lodged at some point in the production conduit 106. Again, while FIG. 2 illustrates a vertical portion of a well, the sliding sleeve technique is often employed in horizontal wells, which increases the difficulty in deploying and retrieving the balls 234. If a ball 234 does become lodged, it may not be possible to retrieve any of the balls that are located downhole of the lodged ball 234. Therefore, it may still be necessary to mill or drill the balls 234 to enable hydrocarbons to be produced.
Therefore, balls and tool components that are dissolvable or degradable in certain fluids have been introduced for use in either plug and perf or sliding sleeve hydraulic fracturing jobs. As noted above, the balls and tool components are subjected to extreme pressures during the hydraulic fracturing process. Therefore, degradable components must be capable of withstanding these conditions before they degrade. Various different types of degradable components have been introduced.
Bubbletight, LLC, assignee of the present application, manufactures tools and balls using a degradable composite metal. The degradable composite metal has exceptional strength characteristics and is useful in a variety of applications. However, it requires a high chloride solution or an acidic solution to degrade in a reasonable time period and it is relatively expensive.
Polymers have also been utilized to manufacture degradable downhole tools and components. One notable degradable polymer that has been utilized for tools and balls is polyglycolic acid (PGA). While PGA has reasonable strength and is less expensive than degradable metal balls, it requires high temperatures (>180° F.) to degrade and even under those conditions it degrades slowly. Polylactic acid (PLA) has also been suggested for use in downhole tools. However, PLA exhibits poor strength and poor degradability and therefore downhole applications have generally been limited to use as a diverter polymer.
While degradable balls and tools have been described in the context of their use in hydraulic fracturing operations, there are also other operations in which degradable downhole tools may be employed. There is therefore a need in the art for degradable downhole tools and components that have desirable strength and degradability properties.